Benzene and ethylene in Bio-SNG production:

nuisance, fuel or valuable products?

L.P.L.M. Rabou & A. van der Drift

Presented at the International Conference on Polygeneration Strategies 11, Vienna

30 August – 1 September 2011

Please do not use this report for reference to the contents of the main text. In-stead, please refer to: Proceedings of the International Conference on Polygeneration Strategies 11, Vienna (2011), p. 157-162. Edited by H. Hofbauer and M. Fuchs. Vienna University of Technology. ISBN: 978-3-9502754-2-1.

ECN-M--11-092

OCTOBER 2011

Benzene and ethylene in bio-SNG production: nuisance, fuel or

valuable products? L.P.L.M. Rabou, A. van der Drift

Energy research Centre of the Netherlands (ECN), PO Box 1, 1755 ZG Petten, The Netherlands.

Abstract:

Gasification of biomass with the aim to produce Substitute Natural Gas (SNG) is best performed at temperatures

around 850°C, where 50% of the combustion value of the producer gas is concentrated in hydrocarbons. After

removal of the heavy hydrocarbons (i.e. tar) and sulphur components, the producer gas can be converted

catalytically to a mixture of mainly methane, carbon dioxide and water. Using producer gas as intermediate instead

of syngas can lead to 10% higher efficiency, as producer gas does contain a significant amount of methane already and because less heat is evolved in the conversion of the remainder than for a mixture of carbon monoxide and

hydrogen.

Some of the hydrocarbons in producer gas, notably benzene, toluene, acetylene and ethylene, together with some of the more volatile tar compounds, can be a nuisance in the conversion step, as they easily form carbon deposits on the

methanation catalysts involved. Several strategies can be followed to make these annoying components useful. Here,

we will focus on benzene and ethylene, as each represents nearly 90% of the total amount of aromatic and unsaturated hydrocarbons respectively in biomass producer gas.

One approach, followed in the SNG demonstration plant in Güssing, is to remove benzene nearly completely from

producer gas in a low-temperature scrubber. Recovered benzene with some of the scrubbing liquid is used as fuel to provide heat for the gasifier. Any benzene remaining in the producer gas and ethylene are converted in the fluidized

bed methanation reactor. The fluidized bed creates conditions in which carbon deposits are gasified before they can

harm the catalyst performance. The use of benzene as heat source in the gasifier reduces the need to burn part of the producer gas for that purpose. Effectively, more "clean" producer gas becomes available for the methanation step.

The MILENA type gasifier developed by ECN has a lower heat demand than the Güssing FICFB gasifier.

Consequently, it has no use for benzene as an additional heat source. That is why ECN research focuses on solving problems associated with the conversion of benzene and ethylene to methane. One of the problems is removal of

organic sulphur compounds, especially thiophene and its derivatives like benzo-thiophene. The main route pursued

by ECN is conversion of thiophenes by a hydrodesulphurization (HDS) catalyst, followed by adsorption of the hydrogensulphide produced.

Benzene removed from producer gas by liquid scrubbing or adsorption to a solid sorbent can also be recovered for

use as fuel in a separate boiler. An advantage of that approach would be that benzene can be stored more easily than producer gas to match heat production with demand by e.g. a district heat system or to provide heat during gasifier

maintenance. In fact, that would copy the approach followed in Harboøre with tar.

Another promising option is cryogenic separation of producer gas. In principle, that would make it possible to separate and recover not only benzene but also ethylene. Even without purification, these may have more value as

chemical base materials than when used as fuel. The cryogenic treatment would probably also capture sulphur

compounds, thus considerably simplifying the gas cleaning needed for protection of the methanation catalyst.

Advantages and disadvantages of the above options will be discussed. Experimental results of ECN research on

hydrodesulphurization and adsorbents will be presented. Further research questions will be addressed.

1. Introduction:

In present-day society fossil fuels are

essential to provide people with food,

healthy living conditions, comfort and

wealth. Increasingly, we become aware of

the shadow sides: the threat of climate

change caused by the rising CO2 level in

the earth atmosphere, dwindling supplies

and the risk of conflicts over the access to

these supplies. Reducing, and ultimately

abolishing, our dependence on fossil fuels

requires a huge efficiency improvement

and the development of other, sustainable,

sources of energy and base materials.

The Energy research Centre of the

Netherlands (ECN) is developing high-

level knowledge and technology for a

sustainable energy system. One of the

research items is technology development

for the production of Substitute Natural

Gas from biomass (bio-SNG). Given the

large share of natural gas in the Dutch

energy consumption, the contribution of

bio-SNG in the Netherlands is expected

to rise quickly and surpass the share of

solid biomass in heat production within

the next decade [1].

The production of bio-SNG starts with

the conversion of biomass into syngas or

producer gas. Here, syngas means a gas

mixture with mainly CO and H2, and

producer gas a mixture of CO and H2 with

methane and other hydrocarbons. Other

components usually present are CO2,

H2O, N2 and various other compounds

containing nitrogen, oxygen, sulphur or

chlorine.

Producer gas is obtained by gasification

at relatively low or medium temperatures,

i.e. between about 700 and 1000°C.

Syngas can be produced by gasification at

high temperatures, usually above 1300°C,

or from producer gas by a (thermal or

catalytic) treatment which breaks down

hydrocarbons into smaller molecules.

Syngas is preferred for the production of

chemicals and liquid fuels. Producer gas

is advantageous for SNG production

because of its substantial hydrocarbon

content [2]. Some of these hydrocarbons

require special attention, to prevent them

from hindering or even deactivating the

methanation catalyst. The present article

is limited to a discussion on hydrocarbons

containing 2 to 8 C-atoms. How to handle

heavier hydrocarbons (tar) is described

e.g. in [3, 4].

2. SNG gasification technology:

A review of the technology developed for

the production of SNG from coal and

biomass can be found in [5]. Application

was limited to one prominent example,

the 3 GW Great Plains Synfuels plant

which started operation in 1984 and

produces 4x106 m

3/day SNG from lignite

(www.dakotagas.com). Further plants

have not been built until recently, when

China showed the wish to become more

self-sufficient in energy.

As application of coal technology to

biomass is not straightforward, several

parties have engaged in the development

of dedicated technology. In Austria, a

1 MW SNG pilot plant was built

downstream the Fast Internally

Circulating Fluidized-Bed (FICFB)

gasifier in Güssing (www.ficfb.at), using

fluidized-bed methanation technology

from PSI in Switzerland [5]. In Sweden,

Göteborg Energi plans to start a 20 MW

plant in 2012, using the same type of

gasifier but different methanation

technology (www.goteborgenergi.se). If

successful, a 200 MW plant will follow.

In the Netherlands, ECN is developing

the MILENA gasifier which uses less

steam and can obtain a higher efficiency

than the FICBF gasifier [6]. Construction

of a 10 MW pilot plant is planned to start

in 2012.

Both the FICFB and MILENA gasifier

can produce virtually N2-free gas without

the need for an air separation plant. At

present, the producer gas needs to be

compressed for conversion into SNG.

That step can be deleted if the gasifiers

are further developed to operate at higher

pressure.

High-pressure biomass gasification has

already been demonstrated in Värnamo,

using an air-blown Circulating Fluidized-

Bed (CFB) gasifier. Conversion of that

gasifier for operation on O2 and steam has

been delayed by lack of funding

(http://lnu.se/research-

groups/chrisgas/project-objectives?l=en).

Co-gasification of coal and biomass at

high temperature and pressure in an

Entrained Flow (EF) gasifier is used to

reduce the CO2 impact of the Buggenum

coal power plant in the Netherlands

(http://www.nuon.com/company/core-

business/energy-generation/power-

stations/buggenum/). Ongoing research

aims to increase the biomass share in the

fuel to 50%, but operation without coal

requires a different concept. Anyhow, the

high temperature produces syngas which

makes the process more suitable for the

production of chemicals and liquid fuels

than SNG.

3. Problem definition

As mentioned in the Introduction, SNG

production from producer gas can be

more efficient because of the hydrocarbon

content. Hydrogenation of hydrocarbons

with 2 or more C-atoms to methane is less

exothermal than the reaction of CO with

H2 to methane. The effect is made clear

by Table 1, which shows the composition

(on dry basis) of MILENA producer gas

by volume and energy content, and the

energy efficiency of conversion to

methane. The non-methane hydrocarbons

contribute one third of the heating value

of the producer gas. Other medium-

temperature gasifiers may produce less tar

and hydrocarbons, but the overall picture

is similar.

Component Vol.

% dry

Energy

%

Eff. %

=>CH4

CO + H2 60 40 77

CH4 13 27 100

C2H2 0.3 1 81

C2H4 4.2 14 89

C2H6 0.3 1 96

C3H6 0.1 0.5 90

C6H6 1.0 8 90

C7H8 0.1 1 91

Tar 0.5 7 91

Tab. 1: Combustible components in

MILENA producer gas and energy

efficiency of conversion to methane.

The contribution of tar to the producer

gas heating value is considerable, but so

are the technical challenges. Given the

effort spent on tar removal for simpler

applications, it is not realistic to suggest

tar conversion into methane. Tar has to be

removed from producer gas. The OLGA

technology, developed by ECN and sold

by Dahlman (www.dahlman.nl), removes

completely all but the most volatile tar

compounds [3]. Removed tar can be used

to cover the gasifier heat demand or

supply process heat.

The other non-methane hydrocarbons

account for 25 to 30% of the energy

content of producer gas. The unsaturated

and aromatic ones are notorious for their

tendency to form carbon deposits (soot or

gum) on nickel methanation catalysts.

Acetylene may be the worst example, but

benzene and ethylene behave similarly

and are present in larger amounts. That's

why this article focuses on them as a

nuisance, at least to begin with.

4. Problem solutions

Solutions to the problems caused by

benzene and ethylene are basically

simple: remove the unwanted compounds

or create conditions which prevent the

formation of carbon deposits.

The second option sounds most attractive,

given the compounds' important

contributions to the gas heating value.

The main factors determining the fate of

benzene and ethylene are the relative

amount of H2 and/or steam and the

temperature. Adding H2 may be an option

to store temporary excess electricity from

renewable sources, but otherwise steam

will have to be used. Research at ECN on

the effect of steam addition makes clear

that finding the right conditions is not

straightforward. Even if steam can solve

the carbon problem, heat use for steam

production will reduce the system

efficiency.

The PSI fluidized-bed methanation

technology may offer a more attractive

solution, by creating conditions for re-

gasification of carbon deposits within part

of the bed [7]. Whether that technology

can handle the amount of benzene given

in Table 1 still remains to be seen, as

benzene was almost completely removed

upstream of the methanation section in

the Güssing pilot SNG plant.

The other option to solve the carbon

problem, removal of the troublesome

components, poses two questions: how to

remove them, and how to dispose of

them?

In the Güssing pilot SNG plant, benzene

and remaining tar compounds are

removed by an RME scrubber working at

5°C. In the Great Plains Synfuels plant,

benzene and other volatile tar compounds

are removed by scrubbing at -40°C with

methanol in the Rectisol gas cleaning

unit. Actually, benzene capture is a side

effect of the process designed to remove

sulphur compounds and CO2. Benzene

and other organic vapours can also be

adsorbed on active carbon. Impregnated

forms of active carbon can be used to

capture sulphur compounds as well.

Each of these three techniques allows

recovery of captured organic compounds

from the working fluid or solid by

distillation or steam stripping. As none of

them is specific for benzene, the product

obtained is a mixture which depends on

the gasifier and upstream gas cleaning.

In Güssing, the mixture is simply used as

fuel in the combustion part of the FICFB

gasifier. There, it covers heat demand

which otherwise is met by burning part of

the producer gas. Effectively, more

producer gas becomes available for the

methanation step.

The lower heat demand of the MILENA

gasifier does not allow that solution.

Neither does a CFB gasifier, where the

recycled mixture could only compete with

biomass char or tar for the limited amount

of oxygen available. Still, the recycled

mixture could be used to generate process

steam, or to cover heat demand elsewhere

or at times when the gasifier is out of

operation. The latter approach is used for

tar at the Harboøre biomass CHP plant

(www.volund.dk). If there is no

reasonable direct use of the benzene

mixture as fuel, reforming with steam to

syngas in a dedicated reactor can be

considered. The syngas can be added to

the producer gas for conversion into

methane.

It should be realized, however, that the

benzene mixture contains organic sulphur

compounds. If the mixture is burned in

the gasifier, it will just add to the sulphur

emissions from biomass char and have to

be treated likewise. If the mixture is used

separately, it requires an installation able

to handle sulphur containing fuel. If the

mixture is to be reformed to syngas,

sulphur will have to be removed before

the methanation catalyst.

If only benzene and light tar compounds

are removed, C2-compounds still have to

be taken care of. Research at ECN shows

that acetylene and ethylene can be made

to react with H2 present in producer gas.

Noble metal catalysts can promote

hydrogenation to C2H6 at about 200°C.

HDS catalysts can also do the job, but

require higher temperature. HDS catalysts

simultaneously promote H2 production by

water-gas shift and conversion of organic

sulphur and nitrogen compounds.

Unfortunately, the catalyst volume

required for operation at atmospheric

pressure is too large for practical

purposes. The effect of higher pressure is

under investigation.

If complete removal of all troublesome

components is required, cryogenic

separation may be the answer. Energy

consumption is significant, but products

with 99% purity can be obtained.

5. Process evaluation

Whether separation processes can be

economical depends on the value and

amount of products that can be obtained

and on the evaded costs. Table 2 shows

the expected product yield for 7000

hours/year operation of a 50 MW biomass

input MILENA gasifier. The amounts of

benzene, toluene and xylene have been

calculated assuming 10%, 30% and 80%

capture by the OLGA tar removal.

Component Amount

tonne/year

C2H2 200

C2H4 3400

C6H6 2200

C7H8 250

C8H10 10

Tab. 2: Expected yearly product yield

of a 50 MW MILENA gasifier.

Market prices of unsaturated and aromatic

hydrocarbons are strongly linked to the

crude oil price. At the end of 2010, prices

were close to 20 €/GJ (~700 €/tonne for

C6H6, C7H8 and C8H10, and ~1000 €/tonne

for C2H4) when the crude oil price was

about 10 €/GJ (90 $/bbl). Acetylene may

be even more valuable, but information

on its bulk price is more difficult to

obtain.

Until a few years ago, natural gas was

about 30% cheaper than oil on energy

basis. Now, the difference is even larger,

making SNG production from ethylene

and benzene seem to be a waste of

money. For the moment, however,

economics are governed by the subsidy or

other support schemes which do exist for

bio-SNG but not yet for bio-chemicals.

Moreover, the market is not yet ready to

accept small streams of limited purity.

That situation may change if more and

larger bio-SNG plants are realized.

Separation of awkward hydrocarbons

from producer gas can increase the useful

life of the methanation catalyst. The use

of noble-metal or HDS catalysts may also

solve (part of) the problem. In the balance

of cost and profit, combination with other

gas cleaning steps, like the removal of

sulphur compounds and CO2, may be the

deciding factor. The optimum solution

will depend on the plant scale, local

conditions and market development.

6. Conclusion and Outlook

Gasification of biomass at moderate

temperatures promises the highest

efficiency for bio-SNG production, but

produces unsaturated and aromatic

hydrocarbons which easily form carbon

deposits on methanation catalysts. Steam

and H2 addition may suppress carbon

formation, but reduce the system

efficiency. Removal of the responsible

compounds, followed by reforming or

use, seems a promising alternative. The

optimum solution will depend on the

gasifier type and plant size.

For small-scale bio-SNG plants, use as

fuel is the obvious choice, provided there

is sufficient heat demand. The alternative

is reforming to syngas in a dedicated

reactor, followed by conversion to

methane.

For large-scale bio-SNG plants, or even

for medium-sized ones in a more mature

market, the nuisance compounds may

become money makers. A quick

inventory shows that the market value of

the compounds can easily be two to three

times the value of the SNG energy

equivalent.

The history of the Great Plains Synfuels

plant proves how the product portfolio

can develop [8]. It now includes aromatic

and phenolic hydrocarbons like discussed

above, CO2, ammonia and sulphur from

the producer gas cleaning, and even

krypton and xenon from the air separation

unit. The plant now uses part of the

syngas to produce ammonia instead of

SNG. In 2008, the coproducts accounted

for 44% of the total revenues

www.dakotagas.com/Products/index.html

It may have taken decades to reach that

point, but it proves that polygeneration

can be a viable option.

7. Acknowledgements

The work reported was performed with

financial support from the Dutch Ministry

of Economic Affairs, Agriculture and

Innovation and from the Energy Delta

Gas Research (EDGaR) program.

8. References

[1] L.W.M. Beurskens and M.

Hekkenberg, report ECN-E--10-069

(2011).

[2] C.M. van der Meijden et al., Biomass

and Bioenergy 34 (2010) p302.

[3] L.P.L.M. Rabou et al., Energy and

Fuels 23 (2009) p6189.

[4] S. Anis and Z.A. Zainal, Ren. Sust.

Energy Rev. 15 (2011) p2355.

[5] J. Kopyscinski et al., Fuel 89 (2010)

p1763.

[6] A. van der Drift et al., Proc. 18th

European Biomass Conference &

Exhibition (2010) p1677.

[7] M.C. Seemann et al., Appl. Cat. A

313 (2006) p14.

[8] G. Baker et al., Proc. 7th

Int.

Pittsburgh Coal Conf. (1990) p.561.

Benzene and ethylene in Bio-SNG production:

nuisance, fuel or valuable products?

L.P.L.M. Rabou & A. van der Drift

Annex

ECN-M--11-092

OCTOBER 2011

www.ecn.nl

Benzene and ethylene in bio-SNG production:

nuisance, fuel or valuable products?

Luc Rabou & Bram van der Drift

31 August 2011

Bio-SNG ≡ CH4 from biomass via gasification

Biomass => “Green” gas

=>

31 August 2011

Biomass “chemistry”

Biomass is almost exactly hydro-carbon = carbon + water

C6(H2O)4

C6H(H2O)4NxSyClz.nH2O + K, Na, P, Ca, Mg, Fe, Si, ….

More exactly:

n = 2.7 ~25% moisture

n = 6.7 ~45% moisture

31 August 2011

Biomass conversion to SNG

C6H(H2O)4.2.7H2O ≈> 3.1 CH4 + 2.9 CO2 + H2O

In theory, biomass with 25% moisture could be decomposed to:

In practice:

31 August 2011

How to get over the mountain (1)

C6H(H2O)4 + O2 + H2O =>

CO + H2

followed by:

n CO + (2n+1) H2 => CnH2n+2 + n H2O

n = 1 for methane,

n ≥ 1 for Fischer-Tropsch

The “easy” way over the top:

a b

n (2n+1) + p CO2 + q H2O

31 August 2011

How to get over the mountain (2)

C6H(H2O)4 + heat + H2O => CO + H2 + CO2 + H2O + CxHy

followed by:

n CO + (2n+1) H2 => CnH2n+2 + n H2O (n = 1 for methane)

and

CxHy + z H2 => x CH4

The “long way over the pass”:

31 August 2011

How to get over the mountain (3)

Either way:

e.g.

• Biomass feeding

• Biomass ash

• Gaseous compounds

of S, Cl, N and

trace elements

• Tar

31 August 2011

Our choice: MILENA indirect gasifier

Combustion air

Flue gas

900°C

Steam

Biomass

Producer gas

825°C

Bed material

900°C

Char + Bed material

Combustion

section

Gasification

section

31 August 2011

MILENA producer gas

Component Vol % (dry)

CO + H2 60

CH4 13

C2H2 0.3

C2H4 4.2

C2H6 0.3

C3H6 0.1

C6H6 1.0

C7H8 0.1

Tar 0.3

CO2 + N2 20

Energy %

40

27

1

14

1

0.5

8

1

6

C2H2 + C2H4 + C3H6 + C6H6 + C7H8 ≡ ± 25% of producer gas heating value

‡ X + H2 => CH4Efficiency‡ %

77

100

81

89

96

90

90

91

91

31 August 2011

OLGA

tar removal

350°C

90°C

SNG using MILENA indirect gasifier

NaO / ZnO

Cl + S

removal

90°C

Ni

methanation 250 - 550°C

CH4 + CO2 + H2O

(+ N2 + CO + H2)

400°C

Combustion air

Flue gas

900°C

Steam

Biomass

Producer gas

825°C

Bed material

900°C

Char + Bed material

31 August 2011

Preliminary design for 12 MW plant

31 August 2011

Early result (2006)

0

25

50

75

100

0 12 24 36 48 60 72 84

Time [hours]

Pre

ssu

re [

hP

a]

Pressure dropSNG reactors

Reactor 1 bypassed

Ni catalyst

blocked by

carbon dust

31 August 2011

Problem analysis

Carbon formation probably caused by:

unsaturated and aromatic hydrocarbons in producer gas

ethylene, acetylene, propene

benzene, toluene, xylene

C2H4, C2H2, C3H6

C6H6, C7H8, C8H10

C2H2+ C2H4+ C3H6+ C6H6+ C7H8 ≡ ± 25% of producer gas heating value

=> Removal would reduce SNG output considerably

31 August 2011

Options

Hydrogenation:

C2H4 + H2 => C2H6 (+ H2 => 2 CH4)

C6H6 + 9 H2 => 6 CH4

Reforming:

C2H4 + 2 H2O => 2 CO + 4 H2

C6H6 + 6 H2O => 6 CO + 9 H2

- In producer gas, with H2 and H2O present or added

- In dedicated reactor, after separation, with added H2 and H2O

31 August 2011

0

1

2

3

4

5

0 50 100 150 200

Test duration [hours]

C2H

4 c

oncentr

ation [%

]

0.0

0.1

0.2

0.3

0.4

0.5

HDS in HDS out SNG1 in SNG1 out

Ethylene conversion in producer gas

1 Hydrogenation to

C2H6 and CH4

by HDS catalyst

2

1

Test lay-out:

HDS H2S-removal Hydrogenation Reforming Methanation

CoMoS ZnO SNG1 (NM1) SNG2 (NM2) SNG3 (Ni)

2 Hydrogenation by

noble-metal catalyst

31 August 2011

Main effect of HDS catalyst

0

2000

4000

6000

8000

0 50 100 150 200

Test duration [hours]

C6H

6 c

oncentr

ation [ppm

]

HDS in

HDS out

Hydrogenation of C2Hx and CO / H2 shift => temperature rise

No effect on benzene (only dilution by increased dry gas volume)

31 August 2011

0

2000

4000

6000

8000

0 50 100 150 200

Test duration [hours]

C6H

6 c

oncentr

ation [ppm

]

SNG1 in SNG1 out

SNG2 out SNG3 out

Benzene conversion in producer gas

2 Conversion by noble-

metal reforming catalyst

2

3

3 Conversion by Ni

methanation catalyst

(with C-formation)

1 No effect of noble-metal

hydrogenation catalyst

1

31 August 2011

Provisional conclusions

• Ethylene hydrogenation achievable

• Benzene conversion complex

• Expensive additional catalysts required

• Separation from producer gas may be needed

• After separation, alternatives may be more attractive

1. Fuel

2. Product10 – 25% of producer gas heating value

31 August 2011

Additional fuel in MILENA: heat balance

Gasifier IN / OUT

Biomass LHV 100

Steam 1

Bed material (net) 15

Producer gas LHV - 85

Gas latent heat - 14

Char LHV - 17

Combustor IN / OUT

Char LHV 17

Tar LHV 6

Air latent heat 4

Bed material (net) - 15

Flue gas latent heat - 11

Heat loss - 1

400°C

Combustion air

Flue gas

900°C

Steam

Biomass

Producer gas

825°C

Bed material

900°C

Char + Bed material

Additional

fuel

31 August 2011

Fuel for heat & power

• Fuel use for district heating

For Dutch consumers:

heat price + distribution costs ≡ natural gas price + distribution costs

=> heat value can be as low as 1/3rd of gas price

• Co-generation, fuel for back-up heat delivery => flexibility

• Co-generation, fuel for steam production => electricity

Value = price of equivalent replacement fuel

31 August 2011

Product (“green” chemicals)

• Ethylene and benzene are important chemicals

• Chemicals more valuable than crude oil

=> certainly more valuable than natural gas

• Products may not be pure

ethylene mixed with acetylene and ethane

benzene mixed with toluene and xylene

• Products may be contaminated

benzene mixed with thiophene

31 August 2011

Expected yield for 50 MW MILENA

50 MW ≡ 100 ktonne/year biomass input

Component Yield

(tonne/year)

C2H2200

C2H43,400

C2H6200

C6H62,200

C7H8250

C8H1010

Substantial amounts, but can they be sold?

Production NL(tonne/year)

~1,000,000

~2,000,000

31 August 2011

The big example

In 2008, co-products accounted for 44% of the total revenues

(but represented only 13% of the fuel energy input)

31 August 2011

Conclusions

• Ethylene and benzene hinder SNG production

• Hydrogenation or reforming can solve problems

• Benzene most difficult compound to handle

• Co-generation or co-production can be more profitable

than just SNG production (without subsidies)

• Nuisance compounds can become moneymakers

• Scale matters

31 August 2011

Summary

31 August 2011

This research has been financed by the Ministry of Economic Affairs, Agriculture and

Innovation, and by a grant of the Energy Delta Gas Research (EDGaR) program.

EDGaR is co-financed by

the Northern Netherlands Provinces,

the European Fund for Regional Development,

the Ministry of Economic Affairs, Agriculture and Innovation,

the Province of Groningen.

English

The research program EDGaR acknowledges the contribution of the

funding agencies:

The Northern Netherlands Provinces (SNN).

This project is co-financed by the European Union, European Fund for

Regional Development and the Ministry of Economic Affairs, Agriculture

and Innovation.

Also the Province of Groningen is co-financing the project.

Nederlands

Het onderzoeksprogramma EDGaR is erkentelijk voor de bijdrage van de

financieringsinstellingen:

Samenwerkingsverband Noord Nederland.

Dit project wordt medegefinancierd door het Europees Fonds voor

Regionale Ontwikkeling en door het ministerie van Economische Zaken,

Landbouw en Innovatie.

Cofinanciering vindt eveneens plaats door de Provincie Groningen.